In this study, we evaluate the potential significance of wellbore orientation and effective-stress-dependent fracture permeability on shale gas production. To do this, we modeled production from the MSEEL MIP-3H gas well using a simple reducedorder- physics discrete-fracture-network (DFN) reservoir model. Parameters for this model were obtained from site data and laboratory triaxial direct-shear tests. Stress-dependent fracture permeability parameters used a scalable exponential decay function that was fitted to the laboratory measurements. Production was then modeled using a modified transient formation linear gas flow equation. Our results indicate that stress-induced fracture closure can cause significant cumulative production loss in certain scenarios, but not in others. When fracture closure is important, aggressive pressure drawdown can rapidly close the fractures and be detrimental to reservoir performance. Furthermore, the orientation of a horizontal well could be optimized for improved recovery by accounting for both the tectonic stresses and natural fractures. Our results are part of a greater effort to identify production strategies that could help to achieve a higher cumulative shale gas production.
Fracture networks have long been attributed as a key factor for the economic hydrocarbon production from low-porosity, low-permeability shale formations because they provide primary fluid flow pathways for improved reservoir performance. This network is comprised of artificially induced hydraulic-fractures and natural fractures, given that the fracking treatment activates natural fractures based on microseismic observations (Rutledge and Phillips, 2003). Therefore, studies have been conducted to improve our understanding of the fracture network in the subsurface. These studies include, but are not limited to, natural fracture (NF) characterization (Gale et al., 2003), hydraulic fracturing (HF) optimization (Warpinski et al., 2009), and the HFNF interactions (Blanton, 1986; Wu and Olson, 2016).
The deliverability of a naturally fractured shale reservoir strongly depends on the effective stress of the fractures. This is because the fractures function as the primary flow paths and their hydromechanical properties are highly susceptible to stress changes. Experiments have shown that the mechanical aperture of a single fracture in various lithologies can change over an order of magnitude when the effective normal stresses varies from 0 to ∼40 MPa (Bandis et al., 1983). Theoretical linear-elastic calculations also indicate that stress-induced closure is more profound for fractures with small aspect ratios (Jaeger et al., 2007). Furthermore, mathematical models have been developed to link fracture stiffness to the hydraulic properties (Pyrak-Nolte and Nolte, 2016).